There are three types of bits which are generally used to drill through subterranean formations. These bit types are: (a) percussion bits (also called impact bits); (b) rolling cone bits, including tri-cone bits; and (c) drag bits or fixed-cutter rotary bits (including core bits so configured), the majority of which currently employ diamond or other superabrasive cutters, polycrystalline diamond compact (PDC) cutters being most prevalent.
In addition, there are other structures employed downhole, generically termed “tools” herein, which are employed to cut or enlarge a borehole or which may employ superabrasive cutters, inserts or plugs on the surface thereof as cutters or wear-prevention elements. Such tools might include, merely by way of example, reamers, stabilizers, tool joints, wear knots and steering tools. There are also formation cutting tools employed in subterranean mining, such as drills and boring tools.
Percussion bits are used with boring apparatus known in the art that move through a geologic formation by a series of successive impacts against the formation, causing a breaking and loosening of the material of the formation. It is expected that the cutter of the invention will have use in the field of percussion bits.
Bits referred to in the art as rock bits, tri-cone bits or rolling cone bits (hereinafter “rolling cone bits”) are used to bore through a variety of geologic formations, and demonstrate high efficiency in firmer rock types. Prior art rolling cone bits tend to be somewhat less expensive than PDC drag bits, with limited performance in comparison. However, they have good durability in many hard-to-drill formations. An exemplary prior art rolling cone bit is shown in FIG. 2. A typical rolling cone bit operates by the use of three rotatable cones oriented substantially transversely to the bit axis in a triangular arrangement, with the narrow cone ends facing a point in the center of the triangle which they form. The cones have cutters formed or placed on their surfaces. Rolling of the cones in use due to rotation of the bit about its axis causes the cutters to imbed into hard rock formations and remove formation material by a crushing action. Prior art rolling cone bits may achieve a rate-of-penetration (ROP) through a hard rock formation ranging from less than one foot per hour up to about thirty feet per hour. It is expected that the cutter of the invention will have use in the field of rolling cone bits as a cone insert for a rolling cone, as a gage cutter or trimmer, and on wear pads on the gage.
A third type of bit used in the prior art is a drag bit or fixed-cutter bit. An exemplary drag bit is shown in FIG. 1. The drag bit of FIG. 1 is designed to be turned in a clockwise direction (looking downward at a bit being used in a hole, or counterclockwise if looking at the drag bit from its cutting end as shown in FIG. 1) about its longitudinal axis. The majority of current drag bit designs employ diamond cutters comprising polycrystalline diamond compacts (PDCs) mounted to a substrate, typically of cemented tungsten carbide (WC). State-of-the-art drag bits may achieve an ROP ranging from about one foot per hour to in excess of one thousand feet per hour. A disadvantage of state-of-the-art PDC drag bits is that they may prematurely wear due to impact failure of the PDC cutters, as such cutters may be damaged very quickly if used in highly stressed or tougher formations composed of limestones, dolomites, anhydrites, cemented sandstones interbedded formations such as shale with sequences of sandstone, limestone and dolomites, or formations containing hard “stringers.” It is expected that the cutter of the invention will have use in the field of drag bits as a cutter, as a gage cutter or trimmer, and on wear pads on the gage.
As noted above, there are additional categories of structures or “tools” employed in boreholes, which tools employ superabrasive elements for cutting or wear prevention purposes, including reamers, stabilizers, tool joints, wear knots and steering tools. It is expected that the cutter of the present invention will have use in the field of such downhole tools for such purposes, as well as in drilling and boring tools employed in subterranean mining.
It has been known in the art for many years that PDC cutters perform well on drag bits. A PDC cutter typically has a diamond layer or table formed under high temperature and pressure conditions to a cemented carbide substrate (such as cemented tungsten carbide) containing a metal binder or catalyst such as cobalt. The substrate may be brazed or otherwise joined to an attachment member such as a stud or to a cylindrical backing element to enhance its affixation to the bit face. The cutting element may be mounted to a drill bit either by press-fitting or otherwise locking the stud into a receptacle on a steel-body drag bit, or by brazing the cutter substrate (with or without cylindrical backing) directly into a preformed pocket, socket or other receptacle on the face of a bit body, as on a matrix-type bit formed of WC particles cast in a solidified, usually copper-based, binder as known in the art.
A PDC is normally fabricated by placing a disk-shaped cemented carbide substrate into a container or cartridge with a layer of diamond crystals or grains loaded into the cartridge adjacent one face of the substrate. A number of such cartridges are typically loaded into an ultra-high pressure press. The substrates and adjacent diamond crystal layers are then compressed under ultra-high temperature and pressure conditions. The ultra-high pressure and temperature conditions cause the metal binder from the substrate body to become liquid and sweep from the region behind the substrate face next to the diamond layer through the diamond grains and act as a reactive liquid phase to promote a sintering of the diamond grains to form the polycrystalline diamond structure. As a result, the diamond grains become mutually bonded to form a diamond table over the substrate face, which diamond table is also bonded to the substrate face. The metal binder may remain in the diamond layer within the pores existing between the diamond grains or may be removed and optionally replaced by another material, as known in the art, to form a so-called thermally stable diamond (“TSD”). The binder is removed by leaching or the diamond table is formed with silicon, a material having a coefficient of thermal expansion (CTE) similar to that of diamond. Variations of this general process exist in the art, but this detail is provided so that the reader will understand the concept of sintering a diamond layer onto a substrate in order to form a PDC cutter. For more background information concerning processes used to form polycrystalline diamond cutters, the reader is directed to U.S. Pat. No. 3,745,623, issued on Jul. 17, 1973, in the name of Wentorf, Jr. et al.
The cutting action in drag bits is primarily performed by the outer semi-circular portion of the cutters. As the drill bit is rotated and downwardly advanced by the drill string, the cutting edges of the cutters will cut a helical groove of a generally semicircular cross-sectional configuration into the formation.
Vibration of the drill bit is a significant problem both to overall performance of the drill bit and drill bit wear life, particularly in drag-type drill bits. The vibration problem of a drill bit becomes more significant when the well bore is drilled at a substantial angle to the vertical, such as in horizontal and directional well drilling. In such drilling the drill bit and the adjacent drill string to the drill bit are acted on by the downward force of gravity and the varying weight on the drill bit. Such conditions produce unbalanced loading of the cutters of the drill bit resulting in radial vibration, typically described as “bit whirl.”
One cause of drill bit vibration is imbalanced cutting forces on the drill bit. Circumferential drilling imbalance forces are always present on drill bits. Such forces tend to push the drill bit towards the side of the well bore. Where the drill bit is provided with a typical cutting structure, gauge cutters on the drill bit are used to cut the edge of the well bore. In this instance, the effective friction between the cutters of the drill bit near the gauge area increases causing the instantaneous center of rotation of the drill bit to translate to a point other than the geometric center of the drill bit resulting in the drill bit to whirl in a reverse or backward rotation motion in the well bore. Whirling of the drill bit continues because the drill bit generates insufficient friction with the well bore by the gauge of the drill bit and the wall of the well bore independent of drill bit orientation in the well bore. The continual change of the center of rotation of the drill bit during whirling causes the cutters of the drill bit to travel faster in a sideways direction and in a backward direction in the well bore, causing increased impact loads on the drill bit.
Gravity also causes vibration of the drill bit when drilling a directional well bore at an angle with respect to the vertical by the radial forces on the drill bit inducing a vertical deflection resulting in drill bit whirl.
Drill bit steering tools further cause drill bit vibration from the steering tool having a bent housing or steering tools connected to the drill bit simulating a bent housing. Vibration of the drill bit results when the bent housing or steering tools simulation of a bent housing are rotated in the well bore causing an off-center rotation of the drill bit and drill bit whirl. Drill bit tilt also creates bit whirl when the drill string is not oriented in the center of the well bore. When this occurs, the end of the drill string and the drill bit are slightly tilted in the well bore.
Surface formation stratification also causes drill bit whirl. When drilling, as the drill bit passes through a comparatively soft formation striking a much harder formation with hard stringers in the formation, the drill bit will whirl because not all the cutters on the drill bit strike the much harder formation or hard stringers at the same time. The uneven striking of the much harder formation or hard stringers by the cutters on the drill bit causes impact forces to be incurred on some of the cutters while locally loading the drill bit, resulting in vibration and drill bit whirl.
All vibration of the drill bit and resulting drill bit whirl shortens drill bit life.
Potential solutions to drill bit vibration and drill bit whirl use various geometries of the cutters of the drill bit to improve their resistance to chipping, while other solutions have been directed at the use of gauge pads and protrusions placed behind the cutters of the drill bit. Other potential solutions to drill bit vibration and drill bit whirl involve the use of shaped cutters on the drill bit with the thinking that the shaped cutter will serve as a stabilizing element on the drill bit. However effective a shaped cutter may be as a stabilizing element on the drill bit, as the shaped cutter wears, any stabilizing force it may create on the drill bit in the well bore decreases.
Improved drill bit stability provided by a cutting element on the drill bit that exhibits minimal change of shape during the drilling of the well bore is desired over the prior art solutions to drill bit vibration and drill bit whirl.